Wednesday, February 12, 2020

Seamless Fluids Prgrams: A Key to Better Well Construction

New insights into displacement mechanics inside casing and in the annulus, combined with integrated drilling and cementing fluid services, can improve primary cementing. This structured "fluids-train" approach also optimizes overal drilling and completion performance at lower cost for operators. 

Improvements in well construction are possible if long standing boundaries between drilling and cementing can be eliminated, and if mud removal and displacement criteria are properly applied. Efficient slurry placement for complete and permanent zonal isolation relies on effective displacement of drilling fluids from the casing-borehole annulus - mud removal - and on avoiding bypassing, mixing and contamination of fluids in the annulus and casing during cement placement. 

Understanding displacement mechanics is essential to successful cementing, but an integrated drilling and cementing fluids approach is a first step toward overall wellbore optimization.

The consequences of poor primary cementing jobs can be severe. Incomplete mud removal may leave channels, allowing communication between subsurface zones or to the surface. Likewise, failure to properly separate fluids as they are pumped downhole can negate the most meticulous plans or the best designs and lead to ineffective mud removaal or contamination that prevents cement from ever setting up (hardening). Approaching well construction as a series of interrelated events in which both mud and cement play important roles - total fluid management- results in a more controllable, structured process with optimal wellbores as the objective. 

Traditionally, drilling fluids and cementing services have been provided separately and the lack of stated, common objectives has been a roadblock to optimizing these operations. Better management of fluid services requires drillers and cementers to work together from well start to finish to select muds that achieve drilling goals, but do not impede cementing success. Consideration must be given to providing gauge holes that allow casing centralization. It may be necesary to reduce rates of penetration - average to high instead of very high- during drilling if that means improved borehole conditions, lower-cost primary cement jobs and reduction or elimination of expensive repair workovers. 

Necessary elements are available and, in most cases, in place to do this; where efforts often fall short is in coordination and management of the entire process to realize maximum benefits. Success in terms of the final product- a safe, long-lasting wellbore at the lowest possible cost - should be an incentive to rethink and restate fluid objectives.

Better understanding of annular displacement is a key element that is already in place. By using physical and computer modeling, cementing criteria have improved. Simulation and design software allow the myriad of fluid factors and complicated interactions involved in primary cementing to be addressed qualitatively, and most of the time quantitatively as well. The total process ( mud removal and cement placement) including conditioning, annular flow regimes, spacer- a buffer between drilling muds and cement slurries- selection and fluid displacement inside pipe can now be evaluated in planning and design stages, during mud maintenance and conditioning, and before or after jobs.

High flow rates effectively displace mud if turbulent flow is achieved around the entire annulus, but are viable only if casing and hole sizes are relatively small and casing standoff from the borehole is adequate.  

Lower flow rates can also successfully remove mud in many cases where higher flow rates are not practical, but more sophisticated designs and modified fluids are often needed to achieve laminar displacements. 

 


 





Sunday, February 9, 2020

The Roots of Gas Migration

Of the two principal objectives facing primary cementing operations- casing support and zonal isolation- the latter usually raises the most concern, and is perhaps the hardest to achieve when there is potential for formation gas to migrate into the cement sheath. The challenge for industry is to achieve a long-term annular cement seal and prevent formation gas entry. Successful handling of gas migration is an evolving science. 

Gas invasion occurs when pressure is lower in the annulus than at the formation face. Gas then migrates either to a lower pressure formation or to the surface. The severity of the problem may range from residual gas pressure of a few psi at the wellhead to a blowout. Whatever the severity, the major factors contributing to gas migration are common. 

Successfully achieving a long-term annular cement seal begins by understanding these contributing factors  and knowing what can be done to minimize or counteract their effects. 

In the past, various techniques have been developed to tackle individual factors that contribute to gas migration. However, gas migration is caused by numerous related factors. Only by addressing each factor systematically can a reasonable degree of success be expected. 

Successfully cementing a well that has potential for gas migration involves a wide range of parameters: fluid density, mud removal strategy, cement slurry design (including fluid-loss control and slurry free water), cement hydration processes, cement-casing-formation bonding and set cement mechanical properties. 

Although gas may enter the annulus by a number of distinct mechanisms, the prerequisites for gas entry are similar. There must be a driving force to initiate the flow of gas, and space within the cemented annulus for the gas to occupy. The driving force comes when pressure in the annulus adjacent to a gas zone falls below the formation gas pressure. Space for the gas to occupy may be within the cement medium or adjacent to it.

To understand how, and under what circumstances, gas entry occurs, a review of the main mechanisms, including cement hydration and resultant pressure decline, follows. First, however, no cementing article is complete without emphasizing that good cementing practices are vital. To effectively cement gas-bearing formations the central pillars of good practice- density control, mud removal and slurry design are critical.



Density: Controlling the driving force- gas can invade and migrate within the cement sheath only if formation pressuree is higher than hydrostatic pressure at the borehole wall. Therefore, as a primary requirement, slurry density must be correctly designed to prevent gas flow during cement placement. However, there is a danger of losing circulation or fracturing an interval if fluid densities are too high. Also, consideration must be given to the free-fall or U-tubing phenomenon that occurs during cement jobs. Therefore, cement jobs should be designed using a placement computer simulator program to assure that the pressure at critical zones remains between the pore and fracture pressures during and immediately after the cement job.

Any density errors made while mixing a slurry on surface may induce large changes in critical slurry properties, such as rheology and setting time. Inconsistent mixing also results in placement of a nonuniform column of cement in the annulus that may lead to soilds settling, free-water development or premature bridging in some parts of the annulus. This is why modern, process-controlled mixing systems that offer accurate density control are proving popular for critical cement operations.

A cement slurry will not transmit hydrostatic pressure forever. The transition from a liquid that controls formation pressure to an impermeable solid is not instantaneous. Consequently, there is a period during which cement loses the ability to transmit pressure. No matter how carefully a slurry has been designed to counterbalance formation pressure, it will not necessarily resist gas invasion throughout the hydration process.



Mud removal : No easy paths for gas - If channels of mud remain in the annulus, the lower yield stresses of drilling fluids may offer a preferential route for gas migration. Furthermore, water may be drawn from the mud channels when they come into contact with cement. This can lead to shrinkage-induced cracking of the mud, which also provides a route gas to flow. 

If the mud filter cake dehydrates after the cement sets, an annulus may form at the formation-cement interface, thus providing another path for gas to migrate. 

How Gas Gets into the Annulus


Understanding the mechanisms of gas migration is complicated by the evolution of the annular cement column with time. The slurry begins as a dense, granular suspension that fully transmits hydrostatic pressure. As the slurry gels, a two-phase material comprised of a solid network with pore fluid forms. Finally , the setting process reaches a point where the cement is for all intents and purposes an impermeable solid. After slurry placement, gas may enter through different mechanisms according to the evolution of the cement's state, the pressures it experiences and other wellbore factors.


Cement state 1: Dense granular fluid

When pumping stops, the cement slurry in the annulus is a dense, granular fluid that transmits full hydrostatic pressure. If formation pore pressure is not greater than this hydrostatic pressure, gas cannot invade. However, almost immediately, pressure within the annulus begins to fall because of a combination of gelation, fluid loss and bulk shrinkage. 

This pressure reduction is best described by the evolution of a wall shear stress (WSS) that begins to support the annular column as the cement slurry gels. In order for a stress to evolve to counteract the hydrostatic pressure, there must be a vertical or axial strain at the annulus walls. This strain is caused by the removal of material during the hydration and setting processes - primarily through fluid loss and shrinkage.

As the cement sets, static gel strength constantly increases, with the rate of increase dependent on the nature of the slurry. There is potential for gas invasion once pressure in the annulus falls below the pressure in the gas-bearing formation. Even with a mud filter cake between the formation and cement, a differential pressure of less than 1 psi may allow gas to invade. The resistance of an external filter cake to gas flow is controlled by the cake's strength and adhesion to the rock face, which both have relatively low values for drilling fluids and neat cements.

This explains the driving force of gas invasion, however, there must also be space within the cemented annulus for gas to occupy. Space is provided by shrinkage, which occurs because the volume of the hydrated phase is generally less than that of the initial reactants.  

Permeability is more complicated issue. Once gelation begins, a cement slurry can be considered as a pseudoporous medium as long as the stress that it must withstand from formation fluid is less than its intrinsic strength. Thus, even though only a partial structure has been formed and the cement column is not yet fully self-supporting, with regard to its flow capacities, it can be said to have permeability. 

Cement slurries display an evolving yield stress that must be overcome before gas entry and flow can occur. Depending on the state of the slurry, gas can migrate by micropercolation, bubbles or fractures. Opportunity for gas entry decreases as the cement cures. 

Cement state 2: A two-phase material

Once a cement column becomes fully self-supporting, it may be considered to act as a matrix of interconnected solid particles containing a fluid phase. Setting continues and hydration accelerates. Pressure, now a pore pressure, decreases further as cement hydration consumes mix water. This leads to an absolute volume reduction or shrinkage of the internal cement matrix by up to 6%. Furthermore, the majority of shrinkage occurs at this stage, leading to tangential tensile stresses in the annulus, which may assist the initiation of fractures and disrupt bonding between the cement and the casing of formation.

Internal shrinkage creates a secondary porosity in the cement composed mainly of conductive pores. At the same time, the volume of water continuously decreases due to hydration, and its ability to move within the pores is reduced by chemical and capillary forces. Shrinkage and water reduction sharply decrease the hydrostatic pressure that cement exerts on formations.

There are two essentially different mechanisms for gas invasion at this stage, depending on the strength of the solid structure and the ease with which pore fluid can be forced through the cement pores by invading gas.

Early in the setting process, while the cement still has a weak soild structure, the possibility of creating fingers or viscoelastic fractures remains. Later, the solid network becomes sufficiently stiff and strong to withstand this effect, and gas invasion and subsequent flow are limited by the impermeability of the solid network to pore fluids. 

Once gas has invaded the porous structure of the cement, it may rise due to buoyancy forces. Alternatively, if the invading gas remains connected through the cement pore space to the gas-bearing formation, the higher pressure in the formation may force gas farther into the annulus. If gas pressure is higher than the minimum compressive stress in the cement and the permeability is too low to allow significant flow, then the cement may fracture. However, this is likely to occur only where residual tensile stresses in the annulus are sufficiently high to allow cracks to open under the influence of the gas pressure.

During the latter stages of this phase, there is a significant and rapid decrease in pore pressure as water is further consumed by hydration. If this occurs while the pore structure is still interconnected, gas may invade and flow rapidly through this pore space. Gas flow may also displace fluid remaining in the pores and prevent complete hydration that would eventually block pore spaces with reaction products.

Cement state 3: An elastic solid

Once hydration is complete, cement becomes an elastic and brittle material that is isotropic, homogeneous and essentially impermeable. In most cases, gas can no longer migrate within the cement matrix and can flow only through interfacial channels or where there has been mechanical failure of the cement.

Regardless of the cement system used, gas can still migrate at the cement-formation or cement-casing interfaces if a microannulus develops, or along paths of weakness where the bond strength is reduced. Both shear and hydraulic bond strengths vary as a function of the same external parameters. Bond strengths increase with effective mud removal, and ith water-wet rather than oil-wet surfaces.

Long-term cement durability is important if a well is to remain safe throughout its life-time. During its active life, a cemented annulus may be subjected to wide variations of temperature and stress from pressure testing, workover operations and variations in producing conditions.

However, field surveys on gas storage wells- which endure some of the most extreme swings in conditions - determined that annular gas leakage occurs early, within the first few cyclic fluctuations in temperature and pressure, rather than over a long period. 






























Resistivity While Drilling- Images from the String

Resistivity measurements made while drilling are maturing to match the quality and diversity of their wireline counterparts. Recent advances include the development of multiple depth-of-investigation resistivity tools for examining invasion profiles, and button electrode tools capable of producing borehole images as the drillstring turns.

It is hard to believe that logging while drilling (LWD) has come such a long way over the last decade. In the early 1980s, LWD measurements were restricted to simple resistivity curves and gamma ray logs, used more for correlation than formation evaluation. Gradually, sophisticated resistivity, density and neutron porosity tools have been added to the LWD arsenal. With the advent of high-deviation, horizontal and now slim multilateral wells, LWD measurements often provide the only means of evaluating reservoirs. The quality and diversity of LWD tools have continued to develop quickly to meet this demand. Today, applications include not only petrophysical analysis, but also geosteering and geological interpretation from LWD imaging. This article focuses on the latest LWD resistivity tools- the RAB Resistivity-at-the-Bit tool and the ARC5 Array Resistivity Compensated tool - and the images they provide.


Geology From the Bit

Simply stated, resistivity tools fall into two categories: laterolog tools that are suitable for logging in conductive muds, highly resistivity formations and resistive invasion; and induction tools which work best in highly conductive formations and can operate in conductive or nonconductive muds. The RAB tool falls into the first category although, strictly speaking, it is an electrode resistivity tool of which laterologs are one type. 

The RAB tool has four main features: 
  • toroidal transmitters that generate axial current- a technique highly suited to LWD resistivity tools.
  • cylindrical focusing that compensates for charateristic overshoots in resistivity readings at bed boundaries allowing accurate true resistivity Rt determination and excellent axial resolution
  • bit resistivity that provides the earliest indication of reservoir penetration or arrival at a casing or coring point - also known for geostopping
  • azimuthal electrodes that produce a borehole image during rotary drilling. 
This last feature allows the RAB tool to be used for geological interpretation. 

Three 1-in. [2.54-cm] diameter buttons are mounted along the axis on one side of the RAB tool. Each button monitors radial current flow into the formation. As the drillstring turns, these buttons scan the borehole wall, producing 56 resistivity measurements per rotation from each button. The data are processed and stored downhole for later retrieval when the RAB tool is returned to the surface during a bit change. Once downloaded to the wellsite workstation, images can be produced and interpreted using standard geological applications like  StrucView Geoframe structural cross section software. 

Wellsite images allow geologists to quickly confirm the structural position of the well during drilling, permitting any necessary directional changes. Fracture identification helps optimize well direction for maximum production.







Monday, January 20, 2020

Drilling and Completions Through Salt

Properties of salt- pseudoplastic flow under subsurface temperatures and pressures, and low permeability - that make salt bodies effective hydrocarbon traps also present unique challenges for oil and gas operators.



 Special considerations, from selecting drilling fluids and bits to implementing casing programs and cementing procedures, are required to produce long-lasting wells. Methods developed on the US Gulf Coast and in the Gulf of Suez, Egypt have improved the efficiency and reliability of drilling and completion operations in thick salt sections. 

Unlike typical sediment sequences in which horizontal stresses are less than vertical stresses from overburden, salt is like a fluid, with stresses in all directions approximately equal to the overburden. Therefore, if borehole fluid pressure is less than in-situ salt strength, stress relaxation may significantly reduce openhole diameters. In some cases, relaxation and salt creep can cause borehole restrictions even before drilling and completion operations are finished. Undergauges boreholes can lead to stuck drillpipe, problems running casing and ultimately casing failures- ovaling, bending or collapse. 

To maintain near-gauge boreholes, drilling fluids must minimize hole closure and washouts. Water - and oil-base muds with saturated and undersaturated salt concentrations, and synthetic fluids have been used to drill salt, but no single system works all the time. Water-base muds with low salt concentrations try to balance salt erosion and dissolution with creep rate to maintain hole size. However, because salt creep and dissolution change across thick salt sections, this can be problematic and hole size may vary with depth.

High-salt-concentration , water-base muds dissolve enough salt to offset creep, but can become undersaturated at high temperatures and enlarge the hole. Oil and synthetic muds dissolution and can be used effectively in salt, but are expensive, can leach water, gas and other mineral inclusions out of salt and may not offset creep. Economic, easy to maintain and adaptable salt-saturated, water-base muds are often used.

Salt is weak and soft, so polycrystalline diamond and other mill-tooth insert cutters, which make hole by scrapping, are used. Stronger inserts may be needed to penetrate caprock formed on the top of some salt layers by groundwater leaching of minerals. Side-cutting, eccentric or bicentered reamers above bits have been proposed to open up hole diameters that are larger than the bit and allow for some salt creep before the borehole becomes undergauge.

After drilling into salt, heavier than expected mud weights may be needed to control salt flow. Drilling speeds vary among operators, but reasonably fast penetration rates - 60 to 150 ft/hr are required, so wells can be cased quickly. Good hole cleaning and periodic back reaming, however, should not be sacrified just to make hole faster. Circulating a small volume of fresh water can remove salt restrictions and free stuck pipe, but care must be used to prevent washouts. Enlarged or undergauge holes make directional control difficult.  

Thick salt bodies can affect temperature and pressure in surrounding formations. Salt thermal conductivity is high compared to other sediments, so overlying formations are heated and underlying formations are cooled. Because salt is a barrier to basin fluids, if outward flow is insufficient to achieve normal compaction, high pressure may develop below salt. As disrupted sediments below salt are penetrated, fluid losses or flow can occur, depending on mud weight and formation pressures, unless drillers proceed slowly and carefully.

Washouts, restrictions, ledges and moving salt exert nonuniform loads on casing. Increasing wall thickness offers better resistance to these loads than higher yield strength steels, so heavy-wall casing can be used if salt creep rates are low and good cement jobs can be obtained. 

In more extreme cases of rapidly moving salt, liners cemented inside cemented casing increase nonuniform load capacity by reducing casing deformation. Collpase resistance of properly cemented concentric strings can equal or exceed the combined strengths of individual liners and casings. Casing across salt zones is subjected to tension, compression, burst and hydrostatic loads combined with nonuniform forces, which must be included in design calculations. Casing can be set just below salt to save time or in deeper formations for better support, depending on the salt interval. A diversion stage tool in the casing string just below the salt may be needed to place specialized cements across the salt, reduce hydrostatic pressure on weaker subsalt intervals or ensure efficient slurry placement.

Effective cement fill in the annulus between the outer casing and borehole minimizes nonuniform load effect. Long slurry thickening times may allow salt to encroach on casing before a complete set occurs, and inadequate displacement across washouts may cause unequal loading or localized bending. Adequate fluid-loss control is needed to prevent excessive loss of slurry mix water that can dissolve or weaken salt, adversely affect cement properties or cause annular bridging, loss of hydrostatic pressure and gas migration. 

Salt saturation cements prevent salt dissolution, but are more difficult to mix on surface and extend slurry set times. Freshwater and low-salt concentration slurries avoid retardation problems and are easier to handle, but long-term exposure to salt may lead to cement failures. 

Additives introduced in the late 1980s helped solve over-retardation and strength development problems in salt-rich slurries. This led to development of proprietary slurries for cementing across salt zones like dowwel saltbond cement system, which provides controllable thickening times, good early compressive strengths, effective placement rheology, excellent fluid-loss control and resistance to aggresive brine attack. 






If the  top of salt appears to be structurally simple based on preliminary time migration, the velocities of the overburden can be used in a poststack depth migration to image the top of salt with good precision. 










If the top of salt is rough, prestack depth migration must be applied. Geologist surmise that such complex topographies indicate instabilities where the upward movement of the salt, once halted, has been reactivated.

Once the top of salt has been imaged, an interpreter must delineate the top of salt on an interactive seismic interpretation workstation. Then the velocity model is updated by filling the volume below the top of salt with salt velocity, assumed to be uniform. With this new model, another prestack - or poststack if overburden velocities are smooth enough - depth migration is performed , and the bottom of salt comes into focus.

An interpreter then maps the bottom of salt. Next, and similar to the first step , velocities of the sedimentary layers below the salt are estimated. These are first approximated by the velocities of layers at the same depth but outside of the canopy of salt. Then a prestack depth migration is run and sets of gathers are checked for flat arrivals. The velocity model is updated at these control points until all control points show flat arrivals on CIP gathers. Then the velocities are interpolated between control points and the full-volume velocity model is complete. 

 
















Sunday, January 19, 2020

Exploring the Subsalt

Advances in seismic imaging have changed the way explorationists view salt bodies. Once seen as impenetrable barriers to geophysical probing with some flanking pay zones, many salt structures are now proving to be thin blankets shielding rich reserves.

 From the earliest days of exploration, prospectors associated salt with oil and gas - but not always for the right reasons. In the 1920s, so many successful wells were drilled around salt domes that logging methods were tuned to identify the high-salinity water in formations overlying pay zones. By 1923, gravity and seismic methods became successful in spotting salt domes, and the industry was on its way to understanding the structural role played by salt. Today, interpreters can view and tour salt structures with the help of powerful graphics workstations. 

Salt is one of the most effective agents in nature for trapping oil and gas: as a ductile material, it can move and deform surrounding sediments, creating traps; salt is also impermeable to hydrocarbons and acts as a seal. Most of the hydrocarbons in North America are trapped in salt-related structures, as are significant amounts in other oil provinces around the world. Many reservoirs in the North Sea are below salt, as are large fields in the Gulf of Suez.

A product of seawater evaporation, salt accumulation can reach thusands of feet in thickness. Salt retains a low density of 2.1 g/cm3 even after burial. However, the surrounding sediments compact and at some depth become denser than the salt - an unstable situation. If the overlying sediments offer little resistance, as is sometimes the case in the gulf of Mexico, the salt rises, creating characteristic domes, pillows and wedges that truncate upturned sedimentary layers. If the overburden does resist, salt can still push through, creating faults in the process. If tectonic conditions are right, extensional faulting in the rigid overburden can open the way for salt ascent. Much of the Zechstein salt pervasive in the North Sea has been mobilized this way.

In contrast to salt's low density is its high seismic wave velocity - 4400 m/sec (14,432 ft/sec) - often more than twice that of surrounding sediments. The strong velocity contrast at the sediment-salt interface acts like an irregularly shaped lens, refracting and reflecting seismic energy.


Early data processing techniques treated this contrast like a mirror, resulting in images that portrayed salt features as bottomless diapirs extending to the deepest level of seismic data. In the 1980s, seismic processing began to correctly image the steeply dipping and sometimes overhanging faces of salt where hydrocarbons could accumulate.



In the last five years, a new image of salt has emerged. In some areas not only is the top of salt cleary visible, but the bottom also. Geologists hypothesize that in these areas of allotchnous salt - found away from its original depositional position- conditions allow the salt, having reached vertical equilibrium, to begin flowing horizontally. 



In the Gulf of Mexico, this occurs mainly in deep water beyond the continental shelf, where sediment cover is not as thick as it is near shore. Wells drilled through thin salt sheets have encountered oil-bearing sediments below.


However, knowledge of the existence of hydrocarbons below salt is insufficient reason to start drilling. Drilling salt is risky. The salt itself is weak and undergoes continuous deformation. Below intruded salt, sediment layers are often disrupted and overpressured. And most important, unless seismic data have been processed to image through the salt, the position of target is unknown. 

A few operators have announced significant oil discoveries beneath salt in the Gulf of Mexico, rekindling a spirit of exploration in the Gulf. Phillips Petroleum Company, in partnership with Anadarko Petroleum Corporation and Amoco Production Company, announced the first commercial Gulf of Mexico subsalt discovery with the Mahogany prospect in 1993, and attributed the success to the imaging technique called prestack depth migration. 

Drilled in 375 ft [114 m] of water to a depth of 16,500 ft [5030 m] , the well produces from sediment layers beneath a salt sheet 3000 to 8000 ft thick.

Since the Mahogany find, many more wells have been drilled in the area, with other operators experiencing similar success. Before prestack depth migration, the success ratio in the subsalt play was around 5%. The new technique is increasing that to 25%. Depth migration is also bringing first-time details to light in some of the many North Sea reservoirs that produce from below salt, and operators plan exploration campaigns in the Red Sea using the same method.

What is this imaging technique and how does it help illuminate subsalt reservoirs? The answers are found in a review of the family of imaging methods, including prestack depth migration, that are bringing subsalt and other complex structures to light.

Imaging

Imaging describes the two seismic data processing steps, stacking and migration, that bring seismic reflections into focus. Stacking attempts to increase signal-to-noise ratio by summing records obtained from several seismic shots reflecting at the same point. Energy arrives on each trace at a different time, depending on the source-receiver separation, or offset. For a uniform velocity layer overlying the reflector, seismic rays are straight, and the arrival times define a hyperbola. The set of traces is called a common midpoint (CMP) gather. Before the CMP gather can be stacked, the traces must be shifted to align arrivals. The offset versus time parameter that describes the shifts defines the stacking velocity of that layer. Shifting is performed for all reflections visible in the traces. The result of stacking is a single trace, taken to represent the signal that would have been recorded in a normal incidence experiment at the midpoint of the source-receiver pairs. The basic assumption in stacking is that velocity does not vary horizontally over the extent of the gather. 

The second component of imaging,migraton, redistributes reflected seismic energy from its recorded position to its true position using a velocity model. There are many classes of migration, varying in environment of applicability from simple structures and smooth velocity variations to complex structures and rapidly varying velocities.

The main distinctions, for the purpose of this article, are the imaging domain- either time or depth- and the order of migration in the work flow- poststack or prestack. To process any one survey, combinations of migration techniques may be used. The trend today, as complex reservoirs come under scrutiny, is to use depth rather than time and prestack instead of poststack. 

In time migration, the velocity model, sometimes called the velocity field, may vary only smoothly. Velocity should increase with depth, and any variations in the horizontal direction should be gradual. The output of the process is a seismic volume with time as the vertical axis. Time migration is most successful when velocities are laterally invariant or smoothly varying. 

In depth migration, the velocity model may have strong velocity contrast vertically or horizontally. Depth migration is suited for environments in which velocities change abruptly, often the case with complex structures such as steep dips, faults, folds, salt intrusions  and truncated layers. 

Imaging a seismic volume containing a salt body is unlike traditional processing, in which thousands of tapes are sent off to a processing group that sends back a finished product, ready for interpretation. Subsalt imaging requires several iterations of migration and interpretation. 

Different operators and service companies may have variants of these methods, but the general processing flow is the same. The first step is to build an initial model of the velocity in the overburden- the velocities of layers overlying the salt. In the North Sea, several major velocity contrasts may overlie the salt. Velocity estimates can come from ray-tracing-based velocity analysis on CMP gathers. If the common midpoint geometry is not suitable, such as when velocities vary horizontally, a CMP gather cannot be used. Instead, a common image point (CIP) gather is created using a prestack migration technique to assemble all the traces that image the depths below a given surface location. 

In the Gulf of Mexico, sediments are typically sand-shale sequences with small velocity contrasts between layers. Without strong velocity contrasts, CMP-based velocity analysis is not necessary, so initial  velocities are taken from stacking velocities. In both cases, velocities are checked for trends with well data such as sonic logs or borehole seismic data. 

 





 
















Monday, January 6, 2020

Advanced Fracturing Fluids Improve Well Economics

The oil and gas industry has witnessed a revolution in fluids technology for hydraulic fracturing. Starting in the mid 1980s, focused research led to major improvements in the performance of well stimulation fluids. Today, new additives and fluids are extending these capabilities and providing innovative solutions to nagging problems. The results are more efficient and cost-effective treatments for enhancing well production. 

Hydraulic fracturing is one of the oil and gas industry's most complex operations. This technique has been applied worldwide to increase well productivity for nearly 50 years. Fluids are pumped into a well at pressures and flow rates high enough to split the rock and create two opposing cracks extending up to 1000 ft [305 m] or more from either side of the borehole. Sand or ceramic particulates, called proppant, are carried by the fluid to pack the fracture, keeping it open once pumping stops and pressure decline. 

What defines a successful fracture? It is one that : 
  • is created reliably and cost-effective
  • provides maximum productivity enhancement
  • is conductive and stable over time.

This article describes today's fracturing operations and the pivotal role played by the fracturing fluid. Then, it highlights four new fluid technologies that are improving fracture success and well economics. 

The Rock, the Mechanics and the Fluid

Historically,  fracturing has been applied primarily to low-permeability - 0.1 to 10 md - formations with the goal of producing narrow, conductive flow paths that penetrate deep into the reservoir. These less restrictive linear conduits replace radial flow regimes and yield a several-fold production increase. For large-scale treatments, as many as 40 pieces of specialized equipment, with a crew of 50 or more, are  required to mix, blend and pump the fluid at more than 50 barrels per minute (bbl/min).

Until recently, treatments were performed almost exclusively on poor producing wells (often to make them economically viable). In the early 1990s, industry focus shifted to good producers and wells with potential for greater financial return. This, in turn, meant an increased emphasis on stimulating high-permeability formations.

The major constraint on production from such such reservoirs is formation damage, frequently remedied by matrix acidizing treatments. But acidizing has limitations, and fracturing has found an important niche. The objective in highly permeable formations is to create short, wide fractures to reach beyond the damage. This is often accomplished by having the proppant bridge, or screen out, at the end, or tip, of the fracture early in the treatment. This "tip screenout" technique is the opposite of what is desired in low-permeability formations where the tip is ideally the last area to be packed.




 Why the different approach? The answer is found in the relationship between fracture length and the permeability contrast between the fracture and the formation. Where the contrast is large, as for low-permeability reservoirs, longer fractures provide proportionally greater productivity. Where the contrast is small, as in high-permeability formations, greater fracture length provides minimal improvement. Fracture conductivity is, however, directly related to fracture width. Using short- about 100 ft- and wide fractures can prove beneficial. 

High-permeability formation treatments are on a far reduced scale. Only a few pieces of blending and pumping equipment are required, and pumping times are typically less than one hour, and often only 15 minutes. Fluid is pumped at 15 to 20 bbl/min with a total volume of 10,000 to 20,000 gal and total proppant weight of about 100,000 lbm. This technique has been successful in the North Sea, Middle East, Indonesia, Canada and Alaska, USA.

While fracturing treatments vary widely in scale, each requires the successful integration of many disciplines and technologies, regardless of reservoir type. Rock mechanics experiments on cores, specialized injection testing and well logs provide data on formation properties. Sophisticated computer software uses these data, along with fluid and well parameters, to simulate fracture initiation and propagation. These results and economic criteria define the optimum treatment design. Process-controlled mixing, blending and high-pressure pumping units execute the treatment. Monitoring and recording devices ensure fluid quality and provide  permanent logs of job results. Engineers tracking the progress of the treatment use graphic displays that plot actual pumping parameters against design values to facilitate real-time decision making. Production simulators compare treatment results with expectations, providing valuable feedback for design of the next job. 

At the heart of this complex process is the fracturing fluid. The fluid, usually water-based, is thickened with high molecular weight polymers, such as guar or hydroxypropyl guar. It must be chemically stable and sufficiently viscous to suspend the propant while it is sheared and heated in surface equipment, well tubulars, perforations and the fracture. Otherwise, premature setling of the proppant occurs, jeopardizing the treatment. A suite of specially designed chemical additives imparts important properties to the fluid. Crosslinkers join polymer chains for greater thickening, fluid-loss agents reduce the rate of filtration into the formation and breakers act to degrade the polymer for removal before the well is placed on production.


 The fracture is created by pumping a series of fluid and proppant stages. The first stage, or pad, initiates and propagates the fracture but does not contain proppant. Subsequent stages include proppant in increasing concentrations to extend the fracture and ensure its adequate packing.

Fracturing fluid technology has also developed in stages. Early work focused on identifying which polymers worked best and what concentrations gave adequate proppant transport. Then, research on additives to fine-tune fluid properties hit high gear. 

Much was learned, but what finally emerged was a huge array of complicated fluids - difficult to prepare and pump - and an amazing assortment of single-use additives ( most had to be custom manufactured) that required expensive material inventories. 

In the past ten years, a more productive research direction has emerged. Oil companies, service companies and polymer manufacturers have concentrated on the basic physical and chemical mechanisms underlying the behaviour of fracturing fluids in an attempt to find improved approaches to fluid design and use. This initiative has led to major advances, including higher-performing polymers, simpler fluids, multifunctional additives and continuous, instead of batch, mixing. These developments have had a significant, beneficial impact on the industry.


  • controlling fluid loss to increase fluid efficiency
  • extending breaker technology to improve fracture conductivity
  • reducing polymer concentration to improve fracture conductivity
  • eliminating proppant flowback to stabilize fractures

Each provides new opportunities for improving well economics, as described in the remainder of this article. 


Controlling Fluid Loss


A portion of the fluid pumped during a fracturing treatment filters into the surrounding permeable rock matrix. This process, referred to as fluid leakoff or fluid loss, occurs at the fracture face. The volume of fluid lost does not contribute to extending or widening the fracture. Fluid efficiency is one parameter describing the fluid's ability to create the fracture. As leakoff increases, efficiency decreases. Excessive fluid loss can jeopardize the treament, increase pumping costs and decrease post-treatment well performance. Typically, particulates or other fluid additives are used to reduce leakoff by forming a filter cake - termed an external cake - on the surface of the fracture face. 

Acting together with the polymer chains, the fluid loss material blocks the pore throats, effetively preventing invasion into the rock matrix. This approach has been applied succssfully for decades to low-permeability (< 0.1 md) formations in which polymer and particulate sizes exceed those of the pore throat. In high-permeability reservoirs, however, fluid constituents may penetrate into the matrix, forming a damaging internal filter cake.This behavior has prompted mechanistic studies to determine the impact on fracturing treatment performance.

Classic fluid-loss theory assumes a two-stage, static -or nonflowing-process. As the fracture propagates and fresh formation surfaces are exposed, an initial loss of fluid, called spurt, occurs until an external filter cake is deposited. Once spurt ceases, pressure drop through the filter cake controls further leakoff. For years, researchers have developed fluid-loss control additives under nonflowing conditions based on this theory.

The conventional assumptions, however, neglect critical factors found under actual dynamic -or flowing - conditions present during fracturing, including the effects of shear stress on both external and internal filter cakes and how fluid-loss additives move toward the fracture face. In high-permeability formations, with an internal filter cake present, most of the resistance to leakoff occurs inside the rock, leaving the external cake subject to erosion by the fluid.

Analysis of fluid loss under dynamic conditions relates external cake thickness to the yield stress of the cake at the fluid interface and the shear stress exerted on the cake by the fluid. These, in turn depend on the physical properties of the cake and the rheological properties of, and shear rate induced in, the fluid. Whether an external filter cake forms, grows, remains stable or erodes depends on the way these parameters vary and interact over time and spatial orientation. 

Similarly, the effectiveness of additives to control fluid loss depends on two factors: their ability to reach the fracture face quickly and their ability to remain there. The former is governed by the drag force exerted on the particles and the latter by the shear force exerted on them. The larger the ratio of drag to shear, the greater the chance that the particles will remain on the surface. A greater leakoff flux to the wall, smaller particle dimensions and a lower shear rate flavor sticking. Promoting higher leakoff for better additive placement seems directly at odds with controlling fluid loss! However, in practice, higher initial leakoff can yield greater overal fluid efficiency.

To confirm the controlling mechanisms, dynamic fluid-loss tests were conducted using a slot-flow geometry , determined to be the simplest representation of what occurs in a fracture. To completely describe the process, computer-controlled equipment was constructed to prepare and test fluids under dynamic conditions, subjecting them to the temperature and shear histories found in a fracture. 

Cores of various lengths were used in the tests to simulate a fracture segment at a fixed distance from the wellbore. As the fracture tip passes a spesific point, spurt occurs and the shear rate reaches a maximum. Then, as the fracture widens, the shear stress decreases.

Laboratory tests show that, for comparable fluids and rocks with permeabilities of up to 50 md, fluid loss is greater than under dynamic conditions than static conditions. Further, examining the impact of shear stress and permeability on the magnitude of fluid loss and the effectiveness of leakoff control additives in high-permeability formations led to five key conclusions.


  1. High shear rates can prevent the formation of an external filter cake and result in higher than expected spurt. 
  2. An internal filter cake controls fluid loss, especially near the fracture tip. 
  3. The effectiveness of fluid-loss additives increases with formation permeability and decreases with shear rate and fluid viscosity.
  4. Reducing fluid loss means reducing spurt, particularly under high shear conditions and in high-permeability formations.
  5. At high shear rates with no external filter cake, efficient spurt control must be achieved by plugging the pore throats at the surface of the rock.



The effects of shear depends on the type of fluid and the formation permeability. Typically, above a threshold shear level, no external filter cake is formed. The magnitude of fluid loss is dependent on the type of polymer and whether it is crosslinked. If the permeability is high enough and the fluid structure degrades with shear, polymer may be able to penetrate the rock matrix.